WO2006112724A2 - Process for production of electric energy and co2 from a hydrocarbon feedstock - Google Patents

Process for production of electric energy and co2 from a hydrocarbon feedstock Download PDF

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Publication number
WO2006112724A2
WO2006112724A2 PCT/NO2006/000142 NO2006000142W WO2006112724A2 WO 2006112724 A2 WO2006112724 A2 WO 2006112724A2 NO 2006000142 W NO2006000142 W NO 2006000142W WO 2006112724 A2 WO2006112724 A2 WO 2006112724A2
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Prior art keywords
stream
rich
air
oxygen
outlet
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PCT/NO2006/000142
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French (fr)
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WO2006112724A3 (en
Inventor
Gelein De Koeijer
Erling Rytter
Børge Rygh SIVERTSEN
Henrik Kobro
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Equinor ASA
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Statoil ASA
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Publication of WO2006112724A3 publication Critical patent/WO2006112724A3/en
Anticipated expiration legal-status Critical
Priority to NO20075953A priority Critical patent/NO20075953L/en
Ceased legal-status Critical Current

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    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F02—COMBUSTION ENGINES; HOT-GAS OR COMBUSTION-PRODUCT ENGINE PLANTS
    • F02C—GAS-TURBINE PLANTS; AIR INTAKES FOR JET-PROPULSION PLANTS; CONTROLLING FUEL SUPPLY IN AIR-BREATHING JET-PROPULSION PLANTS
    • F02C3/00—Gas-turbine plants characterised by the use of combustion products as the working fluid
    • F02C3/20—Gas-turbine plants characterised by the use of combustion products as the working fluid using a special fuel, oxidant, or dilution fluid to generate the combustion products
    • F02C3/22—Gas-turbine plants characterised by the use of combustion products as the working fluid using a special fuel, oxidant, or dilution fluid to generate the combustion products the fuel or oxidant being gaseous at standard temperature and pressure
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    • C01B13/00—Oxygen; Ozone; Oxides or hydroxides in general
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    • C01B13/0229—Purification or separation processes
    • C01B13/0233—Chemical processing only
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    • C01B13/0251—Physical processing only by making use of membranes
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    • C01B13/0229—Purification or separation processes
    • C01B13/0248—Physical processing only
    • C01B13/0259—Physical processing only by adsorption on solids
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    • C01B13/0229—Purification or separation processes
    • C01B13/0288—Combined chemical and physical processing
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    • C01B3/00—Hydrogen; Gaseous mixtures containing hydrogen; Separation of hydrogen from mixtures containing it; Purification of hydrogen; Reversible storage of hydrogen
    • C01B3/02—Production of hydrogen; Production of gaseous mixtures containing hydrogen
    • C01B3/32—Production of hydrogen; Production of gaseous mixtures containing hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide or air
    • C01B3/34—Production of hydrogen; Production of gaseous mixtures containing hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide or air by reaction of hydrocarbons with gasifying agents
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    • C01B3/00—Hydrogen; Gaseous mixtures containing hydrogen; Separation of hydrogen from mixtures containing it; Purification of hydrogen; Reversible storage of hydrogen
    • C01B3/02—Production of hydrogen; Production of gaseous mixtures containing hydrogen
    • C01B3/32—Production of hydrogen; Production of gaseous mixtures containing hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide or air
    • C01B3/34—Production of hydrogen; Production of gaseous mixtures containing hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide or air by reaction of hydrocarbons with gasifying agents
    • C01B3/48—Production of hydrogen; Production of gaseous mixtures containing hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide or air by reaction of hydrocarbons with gasifying agents followed by reaction of water vapour with carbon monoxide
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    • C01B3/50—Separation of hydrogen or hydrogen-containing gases from gaseous mixtures, e.g. purification
    • C01B3/56—Separation of hydrogen or hydrogen-containing gases from gaseous mixtures, e.g. purification by contacting with solids; Regeneration of used solids
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    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
    • C01B2203/02—Processes for making hydrogen or synthesis gas
    • C01B2203/0205—Processes for making hydrogen or synthesis gas containing a reforming step
    • C01B2203/0227—Processes for making hydrogen or synthesis gas containing a reforming step containing a catalytic reforming step
    • C01B2203/0233—Processes for making hydrogen or synthesis gas containing a reforming step containing a catalytic reforming step the reforming step being a steam reforming step
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    • C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
    • C01B2203/02—Processes for making hydrogen or synthesis gas
    • C01B2203/0283—Processes for making hydrogen or synthesis gas containing a CO-shift step, i.e. a water gas shift step
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    • C01B2203/042—Purification by adsorption on solids
    • C01B2203/043—Regenerative adsorption process in two or more beds, one for adsorption, the other for regeneration
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    • C01B2203/0465—Composition of the impurity
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    • C01B2203/0465—Composition of the impurity
    • C01B2203/0475—Composition of the impurity the impurity being carbon dioxide
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    • C01B2203/0465—Composition of the impurity
    • C01B2203/048—Composition of the impurity the impurity being an organic compound
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    • C01B2203/0465—Composition of the impurity
    • C01B2203/0495—Composition of the impurity the impurity being water
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    • C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
    • C01B2203/08—Methods of heating or cooling
    • C01B2203/0805—Methods of heating the process for making hydrogen or synthesis gas
    • C01B2203/0811—Methods of heating the process for making hydrogen or synthesis gas by combustion of fuel
    • C01B2203/0816—Heating by flames
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    • C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
    • C01B2203/08—Methods of heating or cooling
    • C01B2203/0805—Methods of heating the process for making hydrogen or synthesis gas
    • C01B2203/0811—Methods of heating the process for making hydrogen or synthesis gas by combustion of fuel
    • C01B2203/0822—Methods of heating the process for making hydrogen or synthesis gas by combustion of fuel the fuel containing hydrogen
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    • C01B2203/08—Methods of heating or cooling
    • C01B2203/0805—Methods of heating the process for making hydrogen or synthesis gas
    • C01B2203/0811—Methods of heating the process for making hydrogen or synthesis gas by combustion of fuel
    • C01B2203/0827—Methods of heating the process for making hydrogen or synthesis gas by combustion of fuel at least part of the fuel being a recycle stream
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    • C01B2210/00—Purification or separation of specific gases
    • C01B2210/0043—Impurity removed
    • C01B2210/0046—Nitrogen
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
    • F23C—METHODS OR APPARATUS FOR COMBUSTION USING FLUID FUEL OR SOLID FUEL SUSPENDED IN  A CARRIER GAS OR AIR 
    • F23C2900/00—Special features of, or arrangements for combustion apparatus using fluid fuels or solid fuels suspended in air; Combustion processes therefor
    • F23C2900/99011—Combustion process using synthetic gas as a fuel, i.e. a mixture of CO and H2
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
    • F23L—SUPPLYING AIR OR NON-COMBUSTIBLE LIQUIDS OR GASES TO COMBUSTION APPARATUS IN GENERAL ; VALVES OR DAMPERS SPECIALLY ADAPTED FOR CONTROLLING AIR SUPPLY OR DRAUGHT IN COMBUSTION APPARATUS; INDUCING DRAUGHT IN COMBUSTION APPARATUS; TOPS FOR CHIMNEYS OR VENTILATING SHAFTS; TERMINALS FOR FLUES
    • F23L2900/00—Special arrangements for supplying or treating air or oxidant for combustion; Injecting inert gas, water or steam into the combustion chamber
    • F23L2900/07002—Injecting inert gas, other than steam or evaporated water, into the combustion chambers
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02E—REDUCTION OF GREENHOUSE GAS [GHG] EMISSIONS, RELATED TO ENERGY GENERATION, TRANSMISSION OR DISTRIBUTION
    • Y02E20/00—Combustion technologies with mitigation potential
    • Y02E20/16—Combined cycle power plant [CCPP], or combined cycle gas turbine [CCGT]
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02P—CLIMATE CHANGE MITIGATION TECHNOLOGIES IN THE PRODUCTION OR PROCESSING OF GOODS
    • Y02P20/00—Technologies relating to chemical industry
    • Y02P20/10—Process efficiency
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02P—CLIMATE CHANGE MITIGATION TECHNOLOGIES IN THE PRODUCTION OR PROCESSING OF GOODS
    • Y02P20/00—Technologies relating to chemical industry
    • Y02P20/10—Process efficiency
    • Y02P20/129—Energy recovery, e.g. by cogeneration, H2recovery or pressure recovery turbines

Definitions

  • the present invention relates to a process for production of electric energy and CO 2 and an electric power plant for performing the process.
  • a major technical problem associated herewith is the difficulty of separating nitrogen from carbon dioxide.
  • One solution to this problem is a pre-combustion plant, where the CO 2 is removed from a synthesis gas, and where the remaining hydrogen is used for electricity production. The nitrogen-CO 2 mixture is prevented from being formed in this process.
  • WO 00/18680 discloses a process for preparing a hydrogen rich gas and a carbon dioxide rich gas at high pressure comprising separation of synthesis gas obtained by autothermal reforming, air-fired steam reforming or partial oxidation. Further this publication teaches the use of nitrogen for diluting the hydrogen before combustion. How this nitrogen stream is obtained or the quality thereof is not described.
  • WO 99/41188 teaches the use of steam reforming in connection with a hydrogen fueled power plant. Further this publication teaches separating of the obtained synthesis gas into a hydrogen rich stream and a carbon dioxide rich stream with chemical absorption. Part of the obtained hydrogen is used as fuel for heating the steam reformer by combusting the hydrogen with air.
  • JP2003081605 discloses a hydrogen manufacturing method with a steam reformer.
  • the aim of the process is to use the cooling energy present in liquefied natural gas (LNG) to obtain liquid carbon dioxide and hydrogen.
  • LNG liquefied natural gas
  • the obtained synthesis gas is separated by pressure swing adsorption into a hydrogen rich stream and a rest stream at atmospheric pressure.
  • the rest stream is combusted using pure oxygen or high-density oxygen for heating the steam reformer.
  • a CO 2 rich exhaust is produced which is cooled by the cooling energy.
  • the pure or high-density oxygen is produced by cryogenic air separation also using the cooling energy.
  • the use of hydrogen as fuel in a power plant is not disclosed.
  • US6296686 disclose a process for providing an endothermic reaction including transporting oxygen from an air stream through an oxygen selective membrane.
  • Heat is provided by combusting a fuel with either the oxygen transported through the membrane or the rest of the air stream.
  • the object of the process is to provide syngas with a H 2 /C0 molar ratio that requires more heat then the reformation itself can provide and at the same time minimize the formation of NO x .
  • the flue gas comprises a mixture of combustion products including CO 2 and nitrogen from the air stream.
  • the aim of the present invention is to provide a new precombustion process for power production which is applicable for different hydrocarbon feedstocks, which is energy efficient and which comprises recovery of produced CO 2 in form of a CO 2 rich stream that can be stored or used elsewhere. Further the aim is to provide a process that utilizes combustion heat from combusting a rest stream from separation of synthesis gas for heating a steam reformer.
  • the main product from the synthesis gas separation is a carbon lean fuel, which mainly consists of hydrogen.
  • the aim is to provide a process which can be adapted to, at the same time, produce a nitrogen rich stream, preferably oxygen free, for diluting the hydrogen rich and carbon lean fuel before or during combustion to control combustion temperature and formation of nitrogen oxides.
  • the present invention provides a process for production of electric energy and CO 2 from a hydrocarbon feedstock comprising steam reforming of the feedstock producing synthesis gas, wherein the synthesis gas is separated into a hydrogen rich and carbon lean stream and a rest stream, said hydrogen rich and carbon lean stream is combusted with compressed air for producing a combustion product which is expanded in a turbine generating electric energy, said rest stream is recirculated as fuel for producing heat for said steam reforming, characterised in that air is separated into an oxygen rich stream and a nitrogen rich stream, where said oxygen rich stream is used for combusting said rest stream creating a CO 2 rich combustion product.
  • the present invention provides an electric power plant comprising a steam reformer with an inlet for a hydrocarbon feedstock including water and/or steam and an outlet for synthesis gas, said outlet for synthesis gas is in communication with a hydrogen separation unit having an outlet for a hydrogen rich and carbon lean stream and an outlet for a rest stream, said outlet for a hydrogen rich and carbon lean stream is in communication with a combustion chamber for combusting hydrogen with compressed air having an outlet connected to a turbine for generating electric power, said outlet for a rest stream is in communication with a combustion unit heat transferringly connected to said steam reformer, characterised in that the plant further comprises an air separation unit with an outlet for an oxygen rich stream and an outlet for a nitrogen rich stream, wherein said outlet for an oxygen rich stream is in communication with the combustion unit and said combustion unit has an exhaust outlet for a CO 2 rich combustion product.
  • hydrocarbon feedstock is meant to include natural gas, LNG, gasoline, nafta, methane, oil, and bio gas, preferable natural gas.
  • figure 1 is a schematic flow sheet of a first embodiment of the present invention
  • figure 2 is a schematic flow sheet of a second embodiment of the present invention
  • figure 3 is a schematic flow sheet of a third embodiment of the present invention.
  • FIG. 1 illustrates a first embodiment of the present invention.
  • an air stream 40 enters a compressor 5 generating a compressed air stream 45 which is entered into a combustion chamber 4.
  • the compressor 5 may consist of more than one compressor units.
  • a hydrogen rich stream 26 is lead into the combustion chamber 4.
  • Combustion of hydrogen creates exhaust stream 27 which is expanded in a turbine 6.
  • a generator 12 is coupled to the turbine 6.
  • Preferably the generator, the turbine and the compressor are connected to a common shaft.
  • An expanded exhaust stream 28 that leaves the turbine is preferably past into a heat recovery steam generator (HRSG) 7, where the heat contained in the exhaust is used for generating steam which is used for production of electric energy in steam turbines.
  • HRSG heat recovery steam generator
  • the exhaust stream 28 and possible cooled exhaust stream 29 do not contain more carbon dioxide than the amount that is economically viable or is set by regulators.
  • the combustion product when using hydrogen as fuel is water which can be released to the surrounding environment without causing environmental problems.
  • a hydrocarbon feedstock together with steam and/or water is fed to the power plant through conduit 20, it is preferable heated in heat exchanger 30 and enters a steam reformer 1 through conduit 21.
  • the steam reformer synthesis gas is formed and the synthesis gas 22 is optionally cooled in a heat exchanger 31 before it optionally enters a shift reactor unit 2 as stream 23.
  • the shift reactor unit can comprise of one or several stages, e.g. high and low temperature shift reactors.
  • the synthesis gas is shifted by forcing at least part of the CO and H 2 O to form CO 2 and H 2 .
  • the optionally shifted synthesis gas 24 is optionally cooled in a heat exchanger 32 before it is fed as stream 25 into a hydrogen separation unit 3, like a distillation unit, a membrane unit or a pressure swing adsorption (PSA) unit, preferably a PSA unit.
  • the separated hydrogen forms the carbon lean fuel stream 26 to the combustion chamber 4, which may contain maximum 20 mol% CH 4 , CO or CO 2 , but preferably less than 10 mol%.
  • a rest stream 50 containing CO 2 , CO, H 2 O, H 2 and CH 4 is optionally compressed in compressor 60.
  • compressor 60 The work needed to be performed by compressor 60 will depend on the pressure of the rest stream 50, the higher the pressure of stream 50 the less work compressor 60 has to perform.
  • Compressed rest gas 51 is optionally preheated in heat exchanger 35 before it enters a combustion unit 11 as stream 52.
  • the rest stream 52 is combusted in the combustion unit 11 to heat the steam reformer 1. The combustion supplies the necessary extra energy needed for the steam reforming process.
  • An air stream 41, optionally partly compressed in compressor 5 or another compressor is optionally past through a heat exchanger 37 before it enters an air separation unit 9 as stream 42.
  • air is separated into an oxygen rich and nitrogen lean stream 43 and a nitrogen rich stream 19.
  • the oxygen rich and nitrogen lean stream 43 preferably contains more than 90 mol% oxygen.
  • the nitrogen rich stream 19 comprises preferably less than 10 mol% oxygen.
  • Stream 19 may optionally as a whole or partially be expanded in the turbine 6 for generating electricity (not shown on figure 1).
  • the oxygen rich stream 43 is optionally compressed in compressor 62 creating stream 44, which is optionally heated in heat exchanger 33 before it enters the combustion unit 11 as stream 46.
  • Conduit 57 supplies the air separation unit 9 with heat, electricity and/or natural gas depending on the technology used for air separation.
  • the exhaust 53 from the combustion unit 11 will contain predominantly H 2 O and CO 2 , and preferably less than 10 mol% uncombusted fuel and nitrogen.
  • the exhaust is preferably cooled in heat exchanger 36 and a cooled CO 2 rich stream 54 may be compressed in compressor 61 to obtain a compressed supercritical or liquefied CO 2 stream 55 that can be stored, injected into oil or gas containing formations to enhance production or used in any other way.
  • water can be removed from stream 54 as liquid water stream 56, for instance by inserting a condenser (not shown) downstream from the heat exchanger 36.
  • a condenser (not shown) downstream from the heat exchanger 36.
  • uncombusted fuel and nitrogen are present in stream 53, they can optionally be removed in a compression process e.g. by a relatively small distillation unit (not shown).
  • the work needed to be performed by compressor 61 will depend on the pressure of the steam 53.
  • the pressure of stream 53 depends on the pressure of the rest stream 50 and of the oxygen rich stream 46.
  • it may optionally first be expanded in a CO 2 ZH 2 O turbine (not shown) that generates extra electricity.
  • H 2 O can be partially removed and the CO 2 recompressed.
  • This option is preferred if the pressure and temperature of stream 53 are high, preferably above 4 bar and 900 °C respectively.
  • the efficiency of this CO 2 /H 2 O turbine can be optionally increased by combusting the uncombusted fuel (not shown).
  • the air separation unit 9 comprises an oxygen transfer membrane.
  • the membrane is preferably operated at an increased temperature. This may be obtained by passing the optionally compressed air stream 41 through a optional heat exchanger 37.
  • the air stream 42 is brought into contact with the oxygen transfer membrane.
  • Oxygen present in the air stream is transferred through the membrane and leaves the unit as oxygen rich stream 43, which may be pure oxygen.
  • the oxygen depleted air stream leaves the unit 9 as nitrogen rich stream 19.
  • the oxygen transfer membrane can consist of any material capable of transferring oxygen.
  • Known oxygen transfer membranes comprise a membrane preferably arranged on a support material.
  • the membranes that exist today are made of ceramic materials. The membranes can transfer oxygen to a larger absolute pressure on the permeate side than on the retentate side.
  • a concentration gradient will work as the driving force.
  • the stream 43 will contain oxygen and CO 2 and/or steam. If the membrane is swept with CO 2 this will not interfere with the ability of the process to produce a CO 2 rich stream 55, but it only means that a part of the produced CO 2 is recycled. If steam is used for sweeping the stream 53 will contain more H 2 O then without steam sweeping.
  • the rest stream 50 from the hydrogen separation unit can contain some H 2 O, and H 2 O is produced by the combustion. That is if the intent of the process is a pure CO 2 stream some conventional equipment for water separation, like a condenser, must be enclosed downstream from combustion unit 11. If the membrane is swept with steam, this equipment will have to handle somewhat larger amounts of water/steam.
  • the air separation unit 9 comprises a material that physically or chemically absorbs/adsorbs oxygen selectivly. Oxygen is adsorbed and released in a pressure swing operation.
  • the oxygen adsorbing capacity of the material is best at high temperature (500-1000 0 C). This for instance might be achieved by heating the air stream 41 in heat exchanger 37.
  • the adsorbing material can be swept with a CO 2 rich stream like stream 53 or 54, or a steam stream, possibly produced in one of the heat exchangers 31, 32 or in the HRSG system 7.
  • the stream 43 will contain oxygen and CO 2 and/or steam.
  • the separation unit preferably comprises at least two adsorbent beds operated in a dual mode, when adsorption takes place in the first one, desorption takes place in the second one and vice versa.
  • a separation process is known as a Ceramic Autothermal Recovery (CAR).
  • the air separation unit 9 comprises an air separation membrane more permeable to either nitrogen or oxygen.
  • the driving force for the air separation with an air separation membrane is a pressure gradient over the membrane.
  • the air separation unit 9 is a cryogenic air separation unit.
  • compressed air 41 is preferably cooled in heat exchanger 37 before it enters the separation unit 9.
  • the separation of the synthesis gas in a pressure swing adsorption unit 3 is preferably operated in such a way that the rest stream 50 leaving the unit 3 is at a pressure higher than atmospheric pressure, preferably it has a pressure of 1-20 bar, more preferred 1-5 bar.
  • a rest stream with an elevated pressure has the advantage that less work must be performed by compressor 60.
  • Using a rest stream 50 with an elevated pressure is preferably combined with a cryogenic air separation unit.
  • FIG. 2 illustrates a second embodiment of the present invention.
  • the figure shows the power plant according to figure 1 with the same reference numbers, but the power plant further comprises a low temperature catalytic combustion unit 8.
  • At least a part of the nitrogen rich stream 19 from the air separation unit 9 enters combustion unit 8 as stream 19' .
  • any oxygen present in the stream is combusted by using a part 26' of the hydrogen rich stream 26.
  • an oxygen free stream 18 is produced which is used for diluting the rest of the hydrogen rich stream 26 before or in the combustion chamber 4.
  • the fuel stream 90 is cooled in a cooler 38 before it enters the combustion chamber 4 as stream 91. Diluting the hydrogen stream has the advantage that the combustion temperature is more easily controlled and thereby the unwanted generation of nitrogen oxides can be limited.
  • the process performed in the combustion unit 8 is stimulated low temperature combustion, where an oxygen containing nitrogen stream and a hydrogen stream are combusted to form an oxygen free nitrogen stream also containing some H 2 O for diluting the main hydrogen stream.
  • a control system for controlling the flow of the different streams can be installed.
  • the flow of the main hydrogen stream may be controlled by a valve arrange upstream or downstream from the point where the main hydrogen fuel stream is diluted. In one embodiment all valves and other control means can be arranged upstream from the turbine which allows for use of a conventional turbine.
  • stream 19" it is also an option as illustrated by stream 19" to use at least part of the nitrogen rich stream for diluting the fuel and/or cooling of the combustion chamber 4 by adding the stream directly into the chamber 4. Further at least part of the nitrogen rich stream 19 may as illustrated by stream 19'" be expanded in the turbine 6, and thereby act as blade cooling. Any remaining nitrogen rich stream may leave the plant as vent stream 19*.
  • FIG. 3 illustrates a third embodiment of the present invention.
  • the figure shows the power plant according to figure 2, using the same reference numbers for the same units.
  • the air separation unit is a CAR unit, consisting of O 2 absorbent unit 81 and preferably regenerative heaters/coolers 80 and 82.
  • An air stream 70 is compressed in compressor 68 and enters optionally an air heater 69 as stream 71.
  • the heated air stream 72 is entered into the CAR unit where it is heated further in heater 80.
  • Oxygen is absorbed from the air stream as it passes through 81. Heat is recovered in cooler 82 before the oxygen depleted air and nitrogen rich stream 19 leaves the air separation unit.
  • the stream is optionally cooled further in heat exchanger 83 and optionally compressed in compressor 67 before it is optionally used as stream 19', 19" and/or 19'".
  • Oxygen is released from the absorbent unit 81 by using a sweep stream 92.
  • the stream is heated in heater 82.
  • the oxygen rich steam is preferably cooled in cooler 80 before it leaves the air separation unit as stream 43.
  • the stream 43 is compressed and cooled further before it is fed to the combustion unit 11.
  • the sweep stream is obtained from the exhaust stream 53 which preferable is cooled in cooler 64, compressed in compressor 65 and heated in heat exchanger 65 before it is used. The rest of the exhaust stream 53 treated as discussed above.
  • optimised operation conditions for a power plant according to the present invention will in every case depend on the equipment that is used.
  • the following examples show the conditions and results for one system. It will be obvious for a technician skilled in the art that these can vary considerably within the scope of the present invention. The examples are not to be considered limiting for the present invention.
  • the operation conditions of the power plant illustrated on figure 2 are as follows:
  • Air at 15 °C is added to the compressor 5 until the compressed air reaches 17 bara. Thereafter the air 45 is combusted with a fuel 91, which enters at 954 0 C and contains 43 mol% hydrogen, 50 mol% nitrogen, and 0.1 mol% CH 4 .
  • the nitrogen rich hot air 19' added to the catalytic combustor 8 is at 900 0 C, 18.8 bara, and contains 5 mol% O 2 . Vent stream 19* is not present in this case.
  • the exhaust 28 into the HRSG 7 is 581 °C, and leaves at 98 0 C as stream 29.
  • Air separation unit 9 is in this case an Oxygen Transfer Membrane unit, which is swept with a stream containing 41 mol% H 2 O and 56 mol% CO 2 (not shown in figure 2). It enters at 975 °C and 2.0 bara, and is taken from stream 53 (which is first cooled, recompressed and reheated, not shown in figure 2). The minimum ratio of the O 2 pressures in the air and sweep gas is 5.
  • the PSA 3 operates at 50 0 C, producing a rest stream 50 at 1.0 bara with 16 mol% CH 4 , 56% mol% CO 2 , 22 mol% H 2 and 4 mol% CO.
  • the temperature of the synthesis gas 24 out of the shift reactors 2 is 250 °C.
  • the synthesis gas 22 out of the steam reformer is 900 0 C and contains 50 mol% H 2 , 17 mol% CO, 26 mol% H 2 O and 5.5 mol% CH 4 .
  • the entrance conditions of the stream 21 into the steam reformer 1 are 550 °C, 32.5 bara and a steam- to-carbon ratio of 1.8.
  • the temperature of the combustion 11 increases from 650, stream 52, to 1000 °C, stream 53. Compressor 62 is not present in this case.
  • the oxygen rich stream 43 is at 900 0 C, 1.0 bara, containing 80 mol% O 2 , 11 mol% CO 2 and 8 mol% H 2 O.
  • the CO 2 stream 55 is compressed to 110 bara.
  • the operation conditions of the power plant illustrated on figure 3 are as follows: Air at 15 0 C is added to the compressor 5 until the compressed air reaches 17 bara. Thereafter the air is combusted with a fuel, which enters at 280 °C, stream 91 and contains 61 mol% hydrogen, 35 mol% nitrogen, and 0.9 mol% CH 4 .
  • the nitrogen rich hot air 19' added to the catalytic combustor 8 is at 570 °C, 19 bara, and contains 2.5 mol% O 2 . Vent stream 19* is present in this case, while combustion cooling 19" and turbine cooling 19" ' are not.
  • the exhaust 28 into the HRSG 7 is 570 °C, and leaves at 99 °C as stream 29.
  • Air separation unit 80/81/82 is in this case a CAR unit, which is swept with stream 92 containing 2.7 mol% H 2 O, 94 mol% CO 2 , and 2.5 mol% N 2 .
  • the stream enters at 90 °C and 2.2 bara, and is taken from stream 53 after cooling in heat exchanger 64.
  • Energy input stream 57 consists of natural gas and LP steam.
  • the PSA 3 operates at 50 0 C, producing a rest stream 50 at 1.3 bara with 29 mol% CH 4 , 53% mol% CO 2 , 15 mol% H 2 and 1 mol% CO.
  • the temperature of the synthesis gas 24 out of the shift reactors 2 is 250 0 C.
  • the synthesis gas 22 out of the steam reformer is 845 0 C and contains 44 mol% H 2 .
  • the entrance conditions of steam reformer 1 are 550 0 C, 32.5 bara and has a steam-to-carbon ratio of 1.9.
  • the temperature of the combustion outlet 53 is 920 °C. Compressor 62 and heat exchanger 63 are not present in this case.
  • the oxygen rich stream 43 is at 210 0 C, 1.2 bara, containing 25 mol% O 2 , 66 mol% CO 2 and 6 mol% H 2 O.
  • the CO 2 stream 55 is compressed to 110 bara.

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Abstract

A process for the production of electric energy and CO2 from a hydrocarbon feedstock 1 comprising steam reforming of the feedstock producing synthesis gas (22) wherein the the synthesis gas is separated into a hydrogen rich and carbon lean stream (50) said hydrogen rich and carbon lean stream is combusted with compressed air for producing a combustion product which is expanded in a turbine (6) generating electric energy, said rest stream (50) is recirculated as fuel (52) for producing heat for said steam reforming is described. Further a power plant for performing the process is described.

Description

Process for production of electric energy and CO2 from a hydrocarbon feedstock
The present invention relates to a process for production of electric energy and CO2 and an electric power plant for performing the process.
Burning of fossil fuels and release of carbon dioxide into the atmosphere is being associated with global warming and the thereto connected environmental problems. The interest in the development of so called CO2 free solutions is increasing due to the increasing awareness of these problems.
A major technical problem associated herewith is the difficulty of separating nitrogen from carbon dioxide. One solution to this problem is a pre-combustion plant, where the CO2 is removed from a synthesis gas, and where the remaining hydrogen is used for electricity production. The nitrogen-CO2 mixture is prevented from being formed in this process.
WO 00/18680 discloses a process for preparing a hydrogen rich gas and a carbon dioxide rich gas at high pressure comprising separation of synthesis gas obtained by autothermal reforming, air-fired steam reforming or partial oxidation. Further this publication teaches the use of nitrogen for diluting the hydrogen before combustion. How this nitrogen stream is obtained or the quality thereof is not described.
WO 99/41188 teaches the use of steam reforming in connection with a hydrogen fueled power plant. Further this publication teaches separating of the obtained synthesis gas into a hydrogen rich stream and a carbon dioxide rich stream with chemical absorption. Part of the obtained hydrogen is used as fuel for heating the steam reformer by combusting the hydrogen with air.
JP2003081605 discloses a hydrogen manufacturing method with a steam reformer. The aim of the process is to use the cooling energy present in liquefied natural gas (LNG) to obtain liquid carbon dioxide and hydrogen. The obtained synthesis gas is separated by pressure swing adsorption into a hydrogen rich stream and a rest stream at atmospheric pressure. The rest stream is combusted using pure oxygen or high-density oxygen for heating the steam reformer. Thereby a CO2 rich exhaust is produced which is cooled by the cooling energy. The pure or high-density oxygen is produced by cryogenic air separation also using the cooling energy. The use of hydrogen as fuel in a power plant is not disclosed. US6296686 disclose a process for providing an endothermic reaction including transporting oxygen from an air stream through an oxygen selective membrane. Heat is provided by combusting a fuel with either the oxygen transported through the membrane or the rest of the air stream. The object of the process is to provide syngas with a H2/C0 molar ratio that requires more heat then the reformation itself can provide and at the same time minimize the formation of NOx. In the described process the flue gas comprises a mixture of combustion products including CO2 and nitrogen from the air stream.
The aim of the present invention is to provide a new precombustion process for power production which is applicable for different hydrocarbon feedstocks, which is energy efficient and which comprises recovery of produced CO2 in form of a CO2 rich stream that can be stored or used elsewhere. Further the aim is to provide a process that utilizes combustion heat from combusting a rest stream from separation of synthesis gas for heating a steam reformer. The main product from the synthesis gas separation is a carbon lean fuel, which mainly consists of hydrogen. Additionally the aim is to provide a process which can be adapted to, at the same time, produce a nitrogen rich stream, preferably oxygen free, for diluting the hydrogen rich and carbon lean fuel before or during combustion to control combustion temperature and formation of nitrogen oxides.
In a first aspect the present invention provides a process for production of electric energy and CO2 from a hydrocarbon feedstock comprising steam reforming of the feedstock producing synthesis gas, wherein the synthesis gas is separated into a hydrogen rich and carbon lean stream and a rest stream, said hydrogen rich and carbon lean stream is combusted with compressed air for producing a combustion product which is expanded in a turbine generating electric energy, said rest stream is recirculated as fuel for producing heat for said steam reforming, characterised in that air is separated into an oxygen rich stream and a nitrogen rich stream, where said oxygen rich stream is used for combusting said rest stream creating a CO2 rich combustion product.
In another aspect the present invention provides an electric power plant comprising a steam reformer with an inlet for a hydrocarbon feedstock including water and/or steam and an outlet for synthesis gas, said outlet for synthesis gas is in communication with a hydrogen separation unit having an outlet for a hydrogen rich and carbon lean stream and an outlet for a rest stream, said outlet for a hydrogen rich and carbon lean stream is in communication with a combustion chamber for combusting hydrogen with compressed air having an outlet connected to a turbine for generating electric power, said outlet for a rest stream is in communication with a combustion unit heat transferringly connected to said steam reformer, characterised in that the plant further comprises an air separation unit with an outlet for an oxygen rich stream and an outlet for a nitrogen rich stream, wherein said outlet for an oxygen rich stream is in communication with the combustion unit and said combustion unit has an exhaust outlet for a CO2 rich combustion product.
Other embodiments of the present invention are described in the sub-claims.
In connection with the present invention the term "hydrocarbon feedstock" is meant to include natural gas, LNG, gasoline, nafta, methane, oil, and bio gas, preferable natural gas.
The invention will now be described in further detail with reference to the enclosed figures, where: figure 1 is a schematic flow sheet of a first embodiment of the present invention; figure 2 is a schematic flow sheet of a second embodiment of the present invention, and figure 3 is a schematic flow sheet of a third embodiment of the present invention.
Figure 1 illustrates a first embodiment of the present invention. Here an air stream 40 enters a compressor 5 generating a compressed air stream 45 which is entered into a combustion chamber 4. The compressor 5 may consist of more than one compressor units. A hydrogen rich stream 26 is lead into the combustion chamber 4. Combustion of hydrogen creates exhaust stream 27 which is expanded in a turbine 6. A generator 12 is coupled to the turbine 6. Preferably the generator, the turbine and the compressor are connected to a common shaft. An expanded exhaust stream 28 that leaves the turbine is preferably past into a heat recovery steam generator (HRSG) 7, where the heat contained in the exhaust is used for generating steam which is used for production of electric energy in steam turbines. The exhaust stream 28 and possible cooled exhaust stream 29 do not contain more carbon dioxide than the amount that is economically viable or is set by regulators. The combustion product when using hydrogen as fuel is water which can be released to the surrounding environment without causing environmental problems. A hydrocarbon feedstock together with steam and/or water is fed to the power plant through conduit 20, it is preferable heated in heat exchanger 30 and enters a steam reformer 1 through conduit 21. In the steam reformer synthesis gas is formed and the synthesis gas 22 is optionally cooled in a heat exchanger 31 before it optionally enters a shift reactor unit 2 as stream 23. The shift reactor unit can comprise of one or several stages, e.g. high and low temperature shift reactors. In the shift reactor the synthesis gas is shifted by forcing at least part of the CO and H2O to form CO2 and H2. The optionally shifted synthesis gas 24 is optionally cooled in a heat exchanger 32 before it is fed as stream 25 into a hydrogen separation unit 3, like a distillation unit, a membrane unit or a pressure swing adsorption (PSA) unit, preferably a PSA unit. The separated hydrogen forms the carbon lean fuel stream 26 to the combustion chamber 4, which may contain maximum 20 mol% CH4, CO or CO2, but preferably less than 10 mol%. A rest stream 50 containing CO2, CO, H2O, H2 and CH4 is optionally compressed in compressor 60. The work needed to be performed by compressor 60 will depend on the pressure of the rest stream 50, the higher the pressure of stream 50 the less work compressor 60 has to perform. Compressed rest gas 51 is optionally preheated in heat exchanger 35 before it enters a combustion unit 11 as stream 52. The rest stream 52 is combusted in the combustion unit 11 to heat the steam reformer 1. The combustion supplies the necessary extra energy needed for the steam reforming process.
An air stream 41, optionally partly compressed in compressor 5 or another compressor is optionally past through a heat exchanger 37 before it enters an air separation unit 9 as stream 42. In unit 9 air is separated into an oxygen rich and nitrogen lean stream 43 and a nitrogen rich stream 19. The oxygen rich and nitrogen lean stream 43 preferably contains more than 90 mol% oxygen. The nitrogen rich stream 19 comprises preferably less than 10 mol% oxygen. Stream 19 may optionally as a whole or partially be expanded in the turbine 6 for generating electricity (not shown on figure 1). The oxygen rich stream 43 is optionally compressed in compressor 62 creating stream 44, which is optionally heated in heat exchanger 33 before it enters the combustion unit 11 as stream 46. Conduit 57 supplies the air separation unit 9 with heat, electricity and/or natural gas depending on the technology used for air separation.
As the rest gas 52 is combusted using oxygen supplied by the air separation unit 9 the exhaust 53 from the combustion unit 11 will contain predominantly H2O and CO2, and preferably less than 10 mol% uncombusted fuel and nitrogen. The exhaust is preferably cooled in heat exchanger 36 and a cooled CO2 rich stream 54 may be compressed in compressor 61 to obtain a compressed supercritical or liquefied CO2 stream 55 that can be stored, injected into oil or gas containing formations to enhance production or used in any other way.
Depending on the water content and the intended use of the stream 53 water can be removed from stream 54 as liquid water stream 56, for instance by inserting a condenser (not shown) downstream from the heat exchanger 36. In case uncombusted fuel and nitrogen are present in stream 53, they can optionally be removed in a compression process e.g. by a relatively small distillation unit (not shown). The work needed to be performed by compressor 61 will depend on the pressure of the steam 53. The pressure of stream 53 depends on the pressure of the rest stream 50 and of the oxygen rich stream 46. Instead of directly cooling and compressing stream 53, it may optionally first be expanded in a CO2ZH2O turbine (not shown) that generates extra electricity. Subsequently H2O can be partially removed and the CO2 recompressed. This option is preferred if the pressure and temperature of stream 53 are high, preferably above 4 bar and 900 °C respectively. In case uncombusted fuel is present in stream 53, the efficiency of this CO2/H2O turbine can be optionally increased by combusting the uncombusted fuel (not shown).
hi one aspect of the invention the air separation unit 9 comprises an oxygen transfer membrane. The membrane is preferably operated at an increased temperature. This may be obtained by passing the optionally compressed air stream 41 through a optional heat exchanger 37. The air stream 42 is brought into contact with the oxygen transfer membrane. Oxygen present in the air stream is transferred through the membrane and leaves the unit as oxygen rich stream 43, which may be pure oxygen. The oxygen depleted air stream leaves the unit 9 as nitrogen rich stream 19. The oxygen transfer membrane can consist of any material capable of transferring oxygen. Known oxygen transfer membranes comprise a membrane preferably arranged on a support material. The membranes that exist today are made of ceramic materials. The membranes can transfer oxygen to a larger absolute pressure on the permeate side than on the retentate side. A concentration gradient will work as the driving force. Li a preferred embodiment ■ a CO2 rich stream like stream 53 or 54, or a steam stream, possibly produced in one of the heat exchangers 31 or 32 or in the HRSG unit 7, is past along the permeate side of the oxygen membrane. Thereby the membrane surface is swept, the concentration gradient is maintained or increased and the membrane efficiency is increased. In this embodiment the stream 43 will contain oxygen and CO2 and/or steam. If the membrane is swept with CO2 this will not interfere with the ability of the process to produce a CO2 rich stream 55, but it only means that a part of the produced CO2 is recycled. If steam is used for sweeping the stream 53 will contain more H2O then without steam sweeping. The rest stream 50 from the hydrogen separation unit can contain some H2O, and H2O is produced by the combustion. That is if the intent of the process is a pure CO2 stream some conventional equipment for water separation, like a condenser, must be enclosed downstream from combustion unit 11. If the membrane is swept with steam, this equipment will have to handle somewhat larger amounts of water/steam.
In a second aspect of the present invention the air separation unit 9 comprises a material that physically or chemically absorbs/adsorbs oxygen selectivly. Oxygen is adsorbed and released in a pressure swing operation. The oxygen adsorbing capacity of the material is best at high temperature (500-1000 0C). This for instance might be achieved by heating the air stream 41 in heat exchanger 37. To remove and transport the desorbed oxygen out of the separation unit 9 as stream 43, the adsorbing material can be swept with a CO2 rich stream like stream 53 or 54, or a steam stream, possibly produced in one of the heat exchangers 31, 32 or in the HRSG system 7. In this embodiment the stream 43 will contain oxygen and CO2 and/or steam. If the material is swept with CO2 this will not interfere with the ability of the process to produce a CO2 rich stream 55. If steam is used, the stream 53 will contain more H2O. In this aspect the separation unit preferably comprises at least two adsorbent beds operated in a dual mode, when adsorption takes place in the first one, desorption takes place in the second one and vice versa. Such a separation process is known as a Ceramic Autothermal Recovery (CAR).
In another aspect of the present invention the air separation unit 9 comprises an air separation membrane more permeable to either nitrogen or oxygen. The driving force for the air separation with an air separation membrane is a pressure gradient over the membrane.
In yet another aspect of the invention the air separation unit 9 is a cryogenic air separation unit. In this case compressed air 41 is preferably cooled in heat exchanger 37 before it enters the separation unit 9.
The separation of the synthesis gas in a pressure swing adsorption unit 3 is preferably operated in such a way that the rest stream 50 leaving the unit 3 is at a pressure higher than atmospheric pressure, preferably it has a pressure of 1-20 bar, more preferred 1-5 bar. Using a rest stream with an elevated pressure has the advantage that less work must be performed by compressor 60. Preferably it is not necessary to include the compressor 60, and the pressure in the combustion unit 11 is still kept high by a high pressure of stream 50, which lowers the amount of work needed for compressing the CO2 product stream 53. Using a rest stream 50 with an elevated pressure is preferably combined with a cryogenic air separation unit.
Figure 2 illustrates a second embodiment of the present invention. The figure shows the power plant according to figure 1 with the same reference numbers, but the power plant further comprises a low temperature catalytic combustion unit 8. At least a part of the nitrogen rich stream 19 from the air separation unit 9 enters combustion unit 8 as stream 19' . Within the combustion unit 8 any oxygen present in the stream is combusted by using a part 26' of the hydrogen rich stream 26. Thereby an oxygen free stream 18 is produced which is used for diluting the rest of the hydrogen rich stream 26 before or in the combustion chamber 4. Optionally the fuel stream 90 is cooled in a cooler 38 before it enters the combustion chamber 4 as stream 91. Diluting the hydrogen stream has the advantage that the combustion temperature is more easily controlled and thereby the unwanted generation of nitrogen oxides can be limited. The process performed in the combustion unit 8 is stimulated low temperature combustion, where an oxygen containing nitrogen stream and a hydrogen stream are combusted to form an oxygen free nitrogen stream also containing some H2O for diluting the main hydrogen stream. A control system for controlling the flow of the different streams can be installed. The flow of the main hydrogen stream may be controlled by a valve arrange upstream or downstream from the point where the main hydrogen fuel stream is diluted. In one embodiment all valves and other control means can be arranged upstream from the turbine which allows for use of a conventional turbine.
It is also an option as illustrated by stream 19" to use at least part of the nitrogen rich stream for diluting the fuel and/or cooling of the combustion chamber 4 by adding the stream directly into the chamber 4. Further at least part of the nitrogen rich stream 19 may as illustrated by stream 19'" be expanded in the turbine 6, and thereby act as blade cooling. Any remaining nitrogen rich stream may leave the plant as vent stream 19*.
Figure 3 illustrates a third embodiment of the present invention. The figure shows the power plant according to figure 2, using the same reference numbers for the same units. In this embodiment the air separation unit is a CAR unit, consisting of O2 absorbent unit 81 and preferably regenerative heaters/coolers 80 and 82. An air stream 70 is compressed in compressor 68 and enters optionally an air heater 69 as stream 71. The heated air stream 72 is entered into the CAR unit where it is heated further in heater 80. Oxygen is absorbed from the air stream as it passes through 81. Heat is recovered in cooler 82 before the oxygen depleted air and nitrogen rich stream 19 leaves the air separation unit. The stream is optionally cooled further in heat exchanger 83 and optionally compressed in compressor 67 before it is optionally used as stream 19', 19" and/or 19'". Oxygen is released from the absorbent unit 81 by using a sweep stream 92. Preferably the stream is heated in heater 82. The oxygen rich steam is preferably cooled in cooler 80 before it leaves the air separation unit as stream 43. Optionally the stream 43 is compressed and cooled further before it is fed to the combustion unit 11. The sweep stream is obtained from the exhaust stream 53 which preferable is cooled in cooler 64, compressed in compressor 65 and heated in heat exchanger 65 before it is used. The rest of the exhaust stream 53 treated as discussed above.
The optimised operation conditions for a power plant according to the present invention will in every case depend on the equipment that is used. The following examples show the conditions and results for one system. It will be obvious for a technician skilled in the art that these can vary considerably within the scope of the present invention. The examples are not to be considered limiting for the present invention.
Example 1
High temperature OTM as air separation
In one embodiment of the present invention the operation conditions of the power plant illustrated on figure 2 are as follows:
Air at 15 °C is added to the compressor 5 until the compressed air reaches 17 bara. Thereafter the air 45 is combusted with a fuel 91, which enters at 954 0C and contains 43 mol% hydrogen, 50 mol% nitrogen, and 0.1 mol% CH4. The nitrogen rich hot air 19' added to the catalytic combustor 8 is at 900 0C, 18.8 bara, and contains 5 mol% O2. Vent stream 19* is not present in this case. The exhaust 28 into the HRSG 7 is 581 °C, and leaves at 98 0C as stream 29. Air separation unit 9 is in this case an Oxygen Transfer Membrane unit, which is swept with a stream containing 41 mol% H2O and 56 mol% CO2 (not shown in figure 2). It enters at 975 °C and 2.0 bara, and is taken from stream 53 (which is first cooled, recompressed and reheated, not shown in figure 2). The minimum ratio of the O2 pressures in the air and sweep gas is 5. The PSA 3 operates at 50 0C, producing a rest stream 50 at 1.0 bara with 16 mol% CH4, 56% mol% CO2, 22 mol% H2 and 4 mol% CO. The temperature of the synthesis gas 24 out of the shift reactors 2 is 250 °C. The synthesis gas 22 out of the steam reformer is 900 0C and contains 50 mol% H2, 17 mol% CO, 26 mol% H2O and 5.5 mol% CH4. The entrance conditions of the stream 21 into the steam reformer 1 are 550 °C, 32.5 bara and a steam- to-carbon ratio of 1.8. The temperature of the combustion 11 increases from 650, stream 52, to 1000 °C, stream 53. Compressor 62 is not present in this case. The oxygen rich stream 43 is at 900 0C, 1.0 bara, containing 80 mol% O2, 11 mol% CO2 and 8 mol% H2O. The CO2 stream 55 is compressed to 110 bara.
In this particular case 94% of all produced CO2 is captured, and the lower heating value net energy efficiency in this example is 48 %, including CO2 compression and internal losses.
Example 2
Low temperature CAR as air separation
In one embodiment of the present invention the operation conditions of the power plant illustrated on figure 3 are as follows: Air at 15 0C is added to the compressor 5 until the compressed air reaches 17 bara. Thereafter the air is combusted with a fuel, which enters at 280 °C, stream 91 and contains 61 mol% hydrogen, 35 mol% nitrogen, and 0.9 mol% CH4. The nitrogen rich hot air 19' added to the catalytic combustor 8 is at 570 °C, 19 bara, and contains 2.5 mol% O2. Vent stream 19* is present in this case, while combustion cooling 19" and turbine cooling 19" ' are not. The exhaust 28 into the HRSG 7 is 570 °C, and leaves at 99 °C as stream 29. Air separation unit 80/81/82 is in this case a CAR unit, which is swept with stream 92 containing 2.7 mol% H2O, 94 mol% CO2, and 2.5 mol% N2. The stream enters at 90 °C and 2.2 bara, and is taken from stream 53 after cooling in heat exchanger 64. Energy input stream 57 consists of natural gas and LP steam. The PSA 3 operates at 50 0C, producing a rest stream 50 at 1.3 bara with 29 mol% CH4, 53% mol% CO2, 15 mol% H2 and 1 mol% CO. The temperature of the synthesis gas 24 out of the shift reactors 2 is 250 0C. The synthesis gas 22 out of the steam reformer is 845 0C and contains 44 mol% H2. The entrance conditions of steam reformer 1 are 550 0C, 32.5 bara and has a steam-to-carbon ratio of 1.9. The temperature of the combustion outlet 53 is 920 °C. Compressor 62 and heat exchanger 63 are not present in this case. The oxygen rich stream 43 is at 210 0C, 1.2 bara, containing 25 mol% O2, 66 mol% CO2 and 6 mol% H2O. The CO2 stream 55 is compressed to 110 bara.
In this particular case 96% of all produced CO2 is captured, and the lower heating value net energy efficiency in this example is 44 %, including CO2 compression and internal losses.

Claims

C l a i m s
1.
Process for production of electric energy and CO2 from a hydrocarbon feedstock comprising steam reforming of the feedstock producing synthesis gas, wherein the synthesis gas is separated into a hydrogen rich and carbon lean stream and a rest stream, said hydrogen rich and carbon lean stream is combusted with compressed air for producing a combustion product which is expanded in a turbine generating electric energy, said rest stream is recirculated as fuel for producing heat for said steam reforming, characterised in that air is separated into an oxygen rich stream and a nitrogen rich stream, where said oxygen rich stream is used for combusting said rest stream creating a CO2 rich combustion product.
2. Process according to claim 1, characterised in that the process further comprises at least partly converting of CO and H2O present in the synthesis gas into CO2 and H2 before separating the synthesis gas.
3. Process according to claim 1, characterised in that said separation of air is obtained by bringing said air stream in contact with an oxygen transfer membrane (9), which transfers oxygen to a separate stream.
4. Process according to claim 3, characterised in that said separation of air further comprises sweeping the permeate side of said oxygen transfer membrane with a CO2 rich stream or a steam stream.
5. Process according to claim 1, characterised in that said separation of air comprises adsorbing oxygen and desorbing oxygen comprising sweeping with a CO2 rich stream or a steam stream.
6. Process according to claim 1, characterised in that said separation of air comprises bringing the air in contact with an air separation membrane more permeable to oxygen or nitrogen than other air components.
7.
Process according to claim 1, characterised in that said separation of air comprises passing the air into a cryogenic air separation unit.
8.
Process according to any one of the claims 1-7, characterised in that the separation of the synthesis gas is obtained by pressure swing adsorption obtaining said rest stream at a pressure higher than atmospheric pressure.
9.
Process according to claim 8, characterised in that the pressure of the rest stream is 1-20 bar, preferably 1.5-5 bar.
10.
Process according to any one of the claims 1-9, characterised in that at least part of said nitrogen rich stream comprising oxygen together with a part of said hydrogen rich and carbon lean stream is catalytically combusted at low temperature to generate an essentially oxygen free nitrogen stream comprising some water which is mixed with the rest of said hydrogen rich and carbon lean stream.
11.
Process according to any one of the claims 1-10, characterised in that at least part of said nitrogen rich stream is expanded in said turbine for generating electric energy.
12.
Process according to any one of the claims 1-11, characterised in that the process further comprises expanding said CO2 rich combustion product in a CO2ZH2O turbine for generating electric energy, optionally combined with combusting uncombusted fuel in said CO2 rich combustion product.
13.
Electric power plant comprising a steam reformer with an inlet for a hydrocarbon feedstock including water and/or steam and an outlet for synthesis gas, said outlet for synthesis gas is in communication with a hydrogen separation unit having an outlet for a hydrogen rich and carbon lean stream and an outlet for a rest stream, said outlet for a hydrogen rich and carbon lean stream is in communication with a combustion chamber for combusting hydrogen with compressed air having an outlet connected to a turbine for generating electric power, said outlet for a rest stream is in communication with a combustion unit heat transferringly connected to said steam reformer, characterised in that the plant further comprises an air separation unit with an outlet for an oxygen rich stream and an outlet for a nitrogen rich stream, wherein said outlet for an oxygen rich stream is in communication with the combustion unit and said combustion unit has an exhaust outlet for a CO2 rich combustion product.
14. Electric power plant according to claim 13, characterised in that the plant further comprises a shift unit for at least partly converting CO and H2O present in the synthesis gas into CO2 and H2 arranged upstream from the hydrogen separation unit.
15. Electric power plant according to claim 13 or 14, characterised in that the air separation unit comprises an oxygen transfer membrane.
16.
Electric power plant according to claim 13 or 14, characterised in that the air separation unit comprises an oxygen transfer membrane and means for sweeping the permeate side of said membrane with a CO2 rich stream or a steam stream.
17.
Electric power plant according to claim 13 or 14, characterised in that the air separation unit comprises an oxygen adsorption unit and means for sweeping said adsorption unit with a CO2 rich stream or a steam stream.
18.
Electric power plant according to claim 13 or 14, characterised in that the air separation unit comprises an air separation membrane.
19.
Electric power plant according to claim 13 or 14, characterised in that the air separation unit comprises a cryogenic air separation unit.
20.
Electric power plant according to any one of the claims 13-19, characterised in that it further comprises a low temperature stimulated combustion unit comprising an inlet in communication with said outlet for the nitrogen rich stream and with said outlet for an hydrogen rich and carbon lean stream and comprising an outlet in communication with said combustion chamber for combusting hydrogen.
21.
Electric power plant according to any one of the claims 13-20, characterised in that it further comprises a CO2/H2O turbine in communication with said CO2 rich exhaust stream.
PCT/NO2006/000142 2005-04-19 2006-04-19 Process for production of electric energy and co2 from a hydrocarbon feedstock Ceased WO2006112724A2 (en)

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NO20075953A NO20075953L (en) 2005-04-19 2007-11-19 Process for the production of electrical energy and CO2 from a hydrocarbon frame material

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US8163070B2 (en) 2008-08-01 2012-04-24 Wolfgang Georg Hees Method and system for extracting carbon dioxide by anti-sublimation at raised pressure
EP2446122A4 (en) * 2009-06-22 2015-07-15 Echogen Power Systems Inc SYSTEM AND METHOD FOR MANAGING HEAT PROBLEMS IN ONE OR MORE INDUSTRIAL PROCEDURES
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DK171830B1 (en) * 1995-01-20 1997-06-23 Topsoe Haldor As Method for generating electrical energy
JP3944657B2 (en) * 1996-05-17 2007-07-11 石川島播磨重工業株式会社 Power generation facilities that suppress the generation of carbon dioxide
AU6719898A (en) * 1998-02-13 1999-08-30 Norsk Hydro Asa Process for producing electrical power and steam
EP1294637A2 (en) * 2000-06-29 2003-03-26 ExxonMobil Research and Engineering Company Heat exchanged membrane reactor for electric power generation
NO317382B1 (en) * 2001-02-16 2004-10-18 Norsk Hydro As Method for carrying out a catalytic or non-catalytic process
JP3670229B2 (en) * 2001-09-05 2005-07-13 川崎重工業株式会社 Method and apparatus for producing hydrogen with liquefied CO2 recovery

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US8163070B2 (en) 2008-08-01 2012-04-24 Wolfgang Georg Hees Method and system for extracting carbon dioxide by anti-sublimation at raised pressure
EP2446122A4 (en) * 2009-06-22 2015-07-15 Echogen Power Systems Inc SYSTEM AND METHOD FOR MANAGING HEAT PROBLEMS IN ONE OR MORE INDUSTRIAL PROCEDURES
EP2299090A3 (en) * 2009-09-18 2012-01-18 Air Products and Chemicals, Inc. Combustion turbine system with integrated ion transport membrane
EP2663524B1 (en) * 2011-01-10 2018-12-12 Stamicarbon B.V. acting under the name of MT Innovation Center Method for hydrogen production
GB2544802A (en) * 2015-11-27 2017-05-31 Statoil Petroleum As A combustion method
GB2544802B (en) * 2015-11-27 2022-08-17 Equinor Energy As Combusting fuel with oxidant

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